Huge shale resources available and low gas price turn the oil operators' activities to producing more liquid oil. Common enhanced oil recovery methods can be divided along three different techniques: thermal injection, gas injection, and chemical injection to extract oil from the reserves.
Thermal injection uses hot water and steam to extract crude oil from the reservoir. Thermal injection is used for heavily viscous oil that cannot flow on its own, as the increased temperature reduces the oil's viscosity. Thermal injection has dominated the oil recovery market for 2012 and is utilized heavily by Canada, Indonesia, and California. [TMR 2014]. However, given the high price of the natural gas that is needed to heat the steam, its market share is expected to decrease during the next decade.
Gas injection technology injects gases to extract oil. The most common used gas is carbon dioxide (CO2) since it is an abundant byproduct of industrial processes. In Northern America, many of the carbon dioxide enhanced oil recovery projects are concentrated in West Texas.
Chemical injection technology uses polymer, surfactant solution and alkali to extract crude oil from the reservoirs and can be incorporated in conjunction with another injection method for further efficiency.
Presently, North America leads the World in the enhanced oil recovery market, followed by Europe (especially Russia). Currently, it appears there is no necessity for the Middle East to utilize enhanced oil recovery methods for oil extraction (given the region's abundant resources), this is expected to change and it is anticipated that enhanced oil recovery will play a significant role in the Middle East in the coming years.
Currently, to produce a conventional (high-permeability) gas condensate, the conventional practice is inject gas and/or water to flood the gas condensate while maintaining the lower bottom-hole flowing pressure above the dew point pressure. Maintaining the flowing pressure above the dew point pressure is vital since it will prevent the formation of liquid from the initial gas phase, a phenomenon known as retrograde condensate. If this phenomenon were to occur, then valuable oil will be lost since it is more difficult for the formed residual oil saturation to flow to the surface and the formed oil near the wellbore will block further gas flow.
However, keeping the flowing pressure above the dew point results in a lower pressure difference between the reservoir and the flowing pressure. This pressure difference represents the driving force and needs to be high to ensure a higher oil production rate.
Generally when pressure is reduced, a liquid will vaporize to become a gas. However, in some special situation, when the pressure is reduced below a dew point pressure, a liquid forms from an initial gas phase. For instance, such phenomenon would occur by a pressure drop shown in the graph of FIG. 1 from point A to point B. This phenomenon is called retrograde condensate. Such reservoir is called gas condensate reservoir where initially the fluid is in gas state in reservoir. To produce the gas condensate, the conventional practice is to maintain the reservoir pressure or even the bottom-hole well pressure of the production well above the dew point pressure by gas and/or water flooding [Hernandez 1999]. The reason is that, if the reservoir pressure is allowed to decline below the dew point, a considerable volume of valuable condensate may be lost in the reservoir because oil saturation is formed and it is more difficult for the liquid to flow to the surface compared with gas. When oil saturation is below a residual oil saturation, oil cannot be produced using a conventional producing method. In addition, gas productivity declines rapidly once the liquid is formed near the wellbore, because the liquid will block gas flow [Thomas 1995].
In a shale or tight gas condensate reservoir where the formation permeability is very low (nano-Darcy or micro-Darcy), if the well flowing pressure and/or the reservoir pressure is above the dew point pressure, the pressure difference between the reservoir pressure and well flowing pressure which is the drive force to produce gas condensate will be small, especially when the initial reservoir pressure is near the dew point pressure. Then the production rate will be low and the resulting total hydrocarbon recovery will be low as well.
To increase reservoir pressure, there are two methods: gas flooding and huff-n-puff. In the gas flooding, gas is injected through an injector, and fluids are produced from another producer. In the huff-and-puff gas injection, gas is injected to the reservoir through a well during the huff period, and fluids are produced from the same well during the puff period.
Gaseous or gaseous/liquid recovery fluid methods of hydrocarbons is generally divided into two mechanism: (a) drive processes or flooding processes and (b) cyclic processes. The cyclic processes are also known as “huff-n-puff” or “push/pull.” In drive oil recovery processes, injection and production of fluids occur at different wells. In huff-n-puff processes, injection and production of fluids occur through the same well. Besides those structural differences, drive and huff-n-puff processes are substantially different in that the design of slugs of recovery fluid, times of recovery, well patterns, costs, fluid velocities, and other factors are different. Examples of huff-n-puff processes are described and taught in Patton '068 patent, Russum '689 patent, Wehner '863 patent, Shayegi '054 patent, and Miller '431 patent.
In Applicant's recent work of huff-n-puff gas injection in shale oil reservoirs [Sheng 2014; Wan 2013 A; Wan 2013 B; Gamadi 2013; Wan 2014; Gamadi 2014], the pressure effect on oil recovery was studied. It is perceived that, when the flowing pressure is above the minimum miscibility pressure (MMP), the injected gas will be fully miscible with the in-situ oil. Then the oil viscosity will be decreased to the minimum, and the oil will swell to the maximum. The oil recovery will be high. It appears that one of the dominant mechanisms is pressure maintenance. According to the discussions and definitions in Sheng 2011, if the dominant mechanism is pressure maintenance, the gas injection process belongs to improved oil recovery (IOR). If the dominant mechanism is related to miscible flooding, the gas injection process belongs to enhanced oil recovery.
However, the simulation results shown in FIG. 2 show that higher oil recovery is obtained if a lower bottom-hole flowing pressure (BHFP) is used, even though the flowing pressure is lower than the MMP. (For 500 psi, 1000 psi, 1500 psi, and 2500 psi, these are respectively (a) oil recover factors curves 201-204 and (b) oil rates curves 205-208). The main reason is that as the flowing pressure is lower, the pressure difference between the reservoir and this flowing pressure (drive force) will be higher, so that flow rate will be higher according to Darcy's law.
Similarly, in gas condensate reservoirs, to increase gas and oil production, the pressure drop should be high. The wellbore flowing pressure will be lower than the dew point pressure. When that occurs, the liquid oil will be accumulated at the wellbore and the resulting gas saturation will be low. Then gas condensate rate will be lower, the corresponding liquid oil rate will be low as well.
The current available technique to produce gas condensate shale reservoirs is through primary depletion using horizontal wells with multiple transverse fractures. No IOR or EOR methods have been implemented in shale reservoirs. Juell and Whitson [Juell 2013] did simulation work to find optimal operation conditions for gas condensate shale reservoirs is in the depletion mode. They found that the optimal production strategy for wells producing from highly undersaturated gas condensate reservoirs is likely to have an initial period where the flowing pressure equals the saturation pressure, followed by a gradual increase in drawdown, towards the minimum bottom-hole pressure that is operationally possible. When that occurs, the liquid oil will be accumulated at the wellbore, and the resulting gas saturation will be low. Then gas condensate rate will be lower, and the corresponding liquid oil rate will be low as well. To solve this problem, the condensate in conventional condensate reservoirs is re-vaporized by lean gas flooding. [Standing 1948; Weinaug 1949; Smith 1968, nitrogen (Aziz 1982) or CO2 (Chaback 1994; Goricnik 1995)].
However, in shale and tight reservoirs, formation permeability is so low that any flooding (gas flooding and water flooding) may not be feasible because the pressure drop from an injector to a producer is large and thus it is very difficult for the pressure to transport from the injector to the producer. For the huff-n-puff, a quick response from gas injection is expected. The injected gas will increase the pressure near the producer, thus the drive energy is boosted. The increased pressure may vaporize the liquid dropout near the producer. However, there is a concern that the injected gas during the huff period will be re-produced during the puff period.
Thus, there is a need to solve the ultra-low permeability problem in shale reservoirs where gas flooding or water flooding is not feasible to maintain reservoir pressure particularly because liquid oil will drop out in the reservoir and become difficult to produce when the reservoir pressure is low.